It has long been desirable to characterize fluids in a geological formation. For example, in interpreting wellbore monitoring measurements and seismic surveys for phase saturation, the thermodynamic properties of the multicomponent reservoir fluid are required, because the acoustic velocity of the fluid is determined by both the density and the isentropic compressibility, and both velocity and density are needed to decipher seismic data. Thus, it may be inferred that density and isentropic compressibility are fundamental for seismic interpretation. Correspondingly, isothermal fluid compressibility is required for well-test interpretation. In formation testing, early transients are strongly influenced by the fluid within the tool, and interpretation of data requires tool-fluid compressibility. Despite the desirability of obtaining in situ measurements of compressibility of nearly incompressible fluids, such measurements have been generally unavailable. Rather, for measuring compressibility, practice is to bring reservoir fluid samples to the surface laboratory.
When reservoir fluid samples are brought to the surface, pressure and/or temperature changes during the transfer can lead to undesirable component separations and potentially irreversible alterations of the fluid. While gas evolution may be reversed, asphaltene separation from crude oil is generally not reversible within reasonable time-scales. As a result, the results of surface measurements on the fluid can have large uncertainties, even when the fluid is reconstituted.